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PETRONAS FLNG SATU (PFLNG1) is a floating liquefied natural gas facility producing 1.2 million tonnes per annum (mtpa) of LNG, on a facility that is 365m long, and 60m wide, making it among the largest offshore facility ever built. The PFLNG1 project is the first of its kind in the world and is the first deployment of PETRONASâ€™ Floating Liquefied Natural Gas (FLNG) technology, consolidating the traditional offshore to onshore LNG infrastructure into a single facility. This will see a giant floating facility capable of extracting, liquefying and storing LNG at sea, before it is exported to customers around the globe. The FLNG journey has come a long way since 2006, with many technological options explored to monetise and unlock the potential of small and stranded gas fields. Moving an LNG production to an offshore setting poses a demanding set of challenges â€“ as every element of a conventional LNG facility needs to fit into an area roughly one quarter the size in the open seas whilst maintaining safety and increased flexibility to LNG production and delivery.
Take Back Control of Your Capital Project with an EPC 4.0 Strategy Stratigraphical - Sedimentological Framework For The Thamama Group Development In The Western Uae Based On The Legacy Core Data: How The Key To The Future Is Found In The Past. Performance Comparison Of Two Different In-house Built Virtual Metering Systems For Production Back Allocation. Innovation In A Time Of Crisis: How Can The Upstream Industry Develop New, Fit-for-purpose Technology? How To Meet Operational Challenges In An Extreme VUCA Environment By Adaptive Process Control. Challenges In Drilling & Completion Of Extended Reach Drilling Wells With Landing Point Departure More Than 10,000ft In Light/ Slim Casing Design.
The growth and evolution of offshore drilling units have gone from an experiment in the 1940s and 1950s with high hopes but unknown outcome to the extremely sophisticated, high-end technology and highly capable units of the 1990s and 2000s. In less than 50 years, the industry progressed from drilling in a few feet of water depth with untested equipment and procedures to the capability of drilling in more than 10,000 ft of water depth with well-conceived and highly complex units. These advances are a testament to the industry and its technical capabilities driven by the vision and courage of its engineers, crews, and management. From an all-American start to its present worldwide, multinational involvement, anyone involved can be proud to be called a "driller." Since the beginning in the mid-1800s until today, the drilling business commercially has been very cyclic. It has been and still is truly a roller-coaster ride, with rigs being built at premium prices in good economic times and ...
Moharana, Abhishek (Schlumberger) | Mahapatra, Mahabir Prasad (Schlumberger) | Chakraborty, Subrata (Schlumberger) | Biswal, Debakanta (Adani Welspun Exploration Limited) | Havelia, Khushboo (Schlumberger)
Petroleum Geologists typically study hydrocarbon bearing reservoirs, understand the geology, and build numerical models to help better produce hydrocarbon. On the other hand, conventional sedimentologists try to simulate the natural process of sedimentation in laboratory through miniature sand box models to better understand such processes. But a proper integration of the laboratory-based techniques in developing subsurface reservoirs models was always lacking in the industry.
Petroleum geologists developed computer based geostatistical techniques based quantitative statistics like variograms, histograms to develop stochastic models of reservoirs which could be used to put a number and range on the geological uncertainty. However, geostatistics deals more with regularly sampled data, describing their spatial variability and directionality. In development oil fields with many wells sampling the reservoir, geostatistics helps us to create a more predictive subsurface reservoir model. However, in the exploratory state of a field with few drilled wells, the data for geostatistical analysis reduces and a robust conceptual geological is needed to build a predictive subsurface geological model where a proper integration of sedimentology and petroleum geology is required.
Different approaches like conceptual block diagrams of depositional models, average sand distribution maps, training images from present day analogs were tried. However, these were less than optimal, deterministic with a long turnaround time for any robust subsurface reservoir model.
A relatively recent addition to the geologist's set of quantitative tools has been Geologic Process Modeling (GPM), also known as Forward Stratigraphic Modeling (FSM) technique. This technique aims to digitally model the natural processes of erosion, transport and deposition of clastic sediments, as well as carbonate growth and redistribution based on quantitative deterministic physical principles (
In the current study a 3D reservoir model for a field in Western Offshore India was built based on the results of Geological Process Model (GPM) for the thin deltaic reservoir sands as understanding reservoir continuity from seismic data was not possible. With only 4 wells available in the field, traditional geostatistics based reservoir models were inadequate in explaining the reservoir distribution. GPM based techniques helped not only in mapping the reservoir continuity but also opened up new areas for exploration in the area.
Piane, Claudio Delle (CSIRO Energy, Perth, Australia) | Clennell, Ben (CSIRO Energy, Perth, Australia) | Josh, Matthew (CSIRO Energy, Perth, Australia) | Dewhurst, Dave (CSIRO Energy, Perth, Australia)
Recovery of hydrocarbons from organic-rich shales has played a significant role in changing the distribution of reserves worldwide and has also impacted on carbon dioxide emissions where extracted gas has been used to replace coal to power electricity grids. Such extraction is predicated on a good understanding of local and regional geological history as well as close examination of the rocks involved from seismic to nano-scale. This study looks at the impact of thermal maturity on the organic and diagenetic mineral fabrics observed in gas shales from different parts of the world, highlighting similarities and differences in their impacts on rock properties. Organic fabrics can present as pore filling migrated bitumen visualized in scanning and transmission elctron microsopy and the degree of thermal maturity directly impacts for example on the electrical properties, shown by contrasting examples from the Marcellus (ultra-high maturity) and Utica (moderately high maturity) shales; the former has extremely low resitivity while the latter extremely high. Dielectric properties are shown to be useful for rock typing in the Utica shale where standard resistivity logs are off the scale as the material is so resistive. Such properties have also been shown to be useful for estimating water saturation in the Roseneath-Epsilon-Murteree Formations of the Cooper Basin. Mineral diagenesis and its timing are also shown to be important for quartz cementation and pore structure modification in the Marcellus, Bongabinni and Goldwyer formations, with the latter two contrasted in terms of elastic and strength properties. Overall, micro-structural, laboratory and wireline log studies combined have given significant insights into the interplay between organic and diagenetic fabrics and resultant rock properties.
The West Delta Deep Marine concession (WDDM) lies offshore in the Deep water of the present day Nile delta. WDDM consists of many Pliocene submarine channel complexes. The Serpent field is one of those slope marine channels and consists of two separate channels namely channel 12 and channel 13. Channel 12 is divided into three compartments by gravitational faults and channel 13 is composed of two compartments separated by stratigraphic barrier. Gas water contact (GWC) in channelized turbidities reservoir might create an intricate reservoir relationship. Gas water contact becomes complicated when the faults and the facies lateral change provide seals. Those hydrocarbon contacts depths become unpredictable without a distinct system to understand the cause of those variable contacts. Water break-through occurred earlier than expected in Serpent production wells as there was no proper modeling for reservoir facies heterogeneity and facies associated petrophysical parameters. A further compartmentalization of channel 12 arose as the sealing capacity of the gravitational faults cast a doubt over channel-12 compartmentalization and the connected gas initial in place (GIIP). The geological foreknowledge of Serpent field, the production issues and the dire need for further development plans in Serpent field were the motives to initiate this study. Integrated study was designed to answer the unsolved challenges of characterizing the reservoir heterogeneity and faults' sealing capacity. 3-D (three dimensional) high quality seismic data and different seismic attributes were integrated with different well data to build a robust 3-D static model. Static model was the way to elaborate the facies accurate distribution and the different petrophysical parameters in Serpent reservoir. In addition, the 3-D static model was used in the prediction of the faults' sealing capacity through the fault rock facies, fault rock petrophysical properties and transmissibility. In a nutshell, the resultant static model answered the field's issues regarding the early water production, facies heterogeneity and Successfully isolate the different reservoir compartments then run into prediction to assess the potential of the existing well-stock and any future development plans in Serpent field.
Omotosho, Yetunde A. (Department of Petroleum Engineering, University of Ibadan) | Falode, Olugbenga A. (Department of Petroleum Engineering, University of Ibadan) | Ojo, Temilola I. (Covenant University, Canaanland, Otta)
Enhanced Oil Recovery (EOR) methods continue to be dominant in improving world’s oil reserves as producing fields mature. Global growth of 18% was recorded in proved reserves between 2007 and 2017 (BP Statistical Review, 2018), with North America, which has invested in several EOR techniques, contributing about 14% to this growth. This proves that EOR stands as a long-term solution to the menace of dwindling reserves. Recently, nanotechnology has been gaining attention for application in the petroleum industry. It has been established that nanoparticles dispersed in base fluids such as water, brine or certain organic solvents (nanofluid) exhibit some special properties proved to be advantageous for EOR purposes. Additional recovery of about 30% has been recorded. However, permeability damage, which has been widely reported, is yet to be critically studied and analysed.
The objective of this research was to investigate how two important properties; concentration and injection rate of the nanofluid, affect oil recovery, and as well establish the thresholds of conditions which lead to permeability impairment and injection fluid loss during nanoflooding with silica nanoparticles. The permeability impairment layer which is gradually formed at the rock pore surface is termed nanoskin (a concept introduced by the author).
Four core samples were flooded with brine followed by silica nanofluid of four different concentrations viz; 0.01, 0.5, 2.0 amd 3.0% wt/wt respectively. The flooding process was accompanied with changing injection rates viz; 0.5, 1.0, 2.0, 3.0 cm3/min.
The result indicated that concentration of 2.0% wt/wt and injection rate of 2.0 cm3/min were threshold levels that guaranteed optimal oil recovery from the Niger Delta core samples. The overall result demonstrates that nanoflooding is a viable EOR technique and establishes a combination of parameters that will minimize nanoskin formation during nano-EOR process.
Determination of ideal horizontal targets for unconventional reservoirs often necessitates an understanding of the reservoir from the global tectonic to the sub-microscopic scale. When selecting a target zone, it is necessary to consider the abundance, composition, and delivery of sediment to basins; the production, preservation, and alteration of organic matter; and the diagenetic and structural modification of the stratigraphic section. Here, we focus on two sedimentologic phenomena common to the Marcellus Shale of the Appalachian Basin of southwestern Pennsylvania. Namely, we explore the strategy of targeting high organic carbon/biogenic silica facies and the challenges posed by encountering carbonate concretion horizons.
Geochemical observations including Si/Al and Si/Zr, and thin section and scanning electron microscopy indicate abundant recrystallized biogenic quartz cement in the Marcellus Shale. Burial models suggest that prior to the end of mechanical compaction; the Marcellus entered the oil window, and presumably began generating organic matter-hosted porosity at a depth of ~1200m. Notably, at similar organic carbon content, samples with elevated biogenic silica yield higher porosity and permeability. These observations suggest that biogenic quartz may play a role in the deliverability of hydrocarbons by providing a compaction resistant framework conducive to the preservation of organic matter-hosted pores and pore throats. Further, biogenic quartz-rich facies demonstrate increased rates of penetration allowing for more efficient drilling of laterals.
However, carbonate concretions encountered while drilling horizontal Marcellus Shale wells negatively affect drilling operations by reducing drilling rates, damaging bits, and requiring excessive steering corrections to penetrate or extricate the bit from the horizon. Carbonate concretions form by the anaerobic oxidation of methane in a narrow zone perhaps just a few meters below the seafloor. Crucial to this mechanism is a slowing or pause in sedimentation rate that would have held the zone of carbonate precipitation at a fixed depth long enough for concretions to grow. Using this model, we attempt to predict the size and location of concretions to avoid encountering them while drilling. Field observations of Upper Devonian shale-hosted concretion dimensions suggest that Marcellus-hosted concretions up to three feet in length are possible. Hiatuses in sedimentation and potential concretion horizons were predicted using uranium to organic carbon ratios. The attachment of uranium to organic carbon macerals occurs across the sediment-water interface. Therefore, an increase in the abundance of uranium per unit organic carbon indicates a cessation in sedimentation and the potential for concretion growth. Indeed, when comparing well log response to core, uranium to organic carbon excursions predicted the location of two concretion horizons.
Submersibles have application in a limited number situations. There are only seven submersibles left in existence, all located in the Gulf of Mexico. The water depth range for submersibles is between 9 and 85 ft, with a lesser depth rating during hurricane season. Despite their narrow water depth range, they still serve an important, although limited, segment of the market. Most jackup rigs cannot operate in less than 18 to 25 ft of water, although a very few can move into as little as 14 ft. of water.
Scope of this paper is to show how the proper definition of reservoir rock types, based on core data and integrated with nuclear magnetic resonance (NMR) log results, is able to provide a reliable strategic estimation of permeability in un-cored wells where only conventional logs are available. The target is to optimize the perforated intervals by means of a robust discrimination between movable and unmovable fluids and consequent detection of the reservoir zones characterized by the best gas deliverability potential. Mercury injection capillary pressure measurements have been used to evaluate the core pore throat size distribution and to separate micro from macro porosity. The integration of these information with NMR, acquired on the same core, allows to calibrate the most efficient T2 cutoff, discriminating movable from the unmovable fluids. The final outcome is a robust link between reservoir properties (defined and directly measured on core data) and log classification, giving a key driver for the definition of a synthetic permeability profile, rock type dependent, and applied for perforated interval optimization in wells where no cores are available. The blind test was a comparison between estimated permeability from the well production performance and permeability derived from NMR logs, showing a good match. The work has greatly increased the value of NMR acquisition in Gas industry, showing how a proper T2 Cutoff core/log calibration is a vital factor to get the benefit of NMR in Gas reservoirs permeability prediction, providing a useful driver for perforated interval optimization.